Technical Field
The present invention relates to processes and techniques for oil recovery. More specifically, combined supercritical CO2 and surfactant solution injection strategies are deployed in these processes to effectively displace oil from reservoirs of high salinity.
Description of the Related Art
The “background” description provided herein is for the purpose of generally presenting the context of the disclosure. Work of the presently named inventors, to the extent it is described in this background section, as well as aspects of the description which may not otherwise qualify as prior art at the time of filing, are neither expressly or impliedly admitted as prior art against the present invention.
Crude oil development and production in global oil reservoirs can include up to three distinct phases: primary, secondary and tertiary (or enhanced) recovery. During primary recovery, reservoir drive comes from a number of natural mechanisms. These include: natural water displacing oil downward into the well, expansion of the natural gas at the top of the reservoir, expansion of gas initially dissolved in the crude oil, and gravity drainage resulting from the movement of oil within the reservoir from the upper to the lower parts where production wells are located. Only about 10% (e.g. 5-15%) of a reservoir's original oil in place is typically produced by the natural mechanisms of primary recovery. Secondary techniques extend a field's productive life after the natural reservoir drive diminishes, generally by injecting external energy in the form of water (e.g. water injection or waterflooding) or gas to increase the reservoir pressure, so that the oil can be artificially displaced and driven to a production wellbore, resulting in the recovery of 20-40% of the original oil in place.
As the global energy demand continues to surge and the amount of easy-to-produce oil (by primary and secondary recoveries) diminishes rapidly, oil producers are investing and searching for methods to increase oil recovery, including the recovery of residual oil from a growing number of mature oil fields that have already been subjected to primary and secondary recoveries. The residual oil is usually heavy: having high viscosity and therefore resulting in low oil mobility.
Techniques in enhanced oil recovery (EOR) offer prospects for ultimately producing 30-60%, or more, of the reservoir's original oil in place. EOR processes attempt increase the recovery factor by focusing on the rock/oil/injectant system (e.g. wettability of reservoir rocks) as well as the interplay of capillary and viscous forces (i.e. to reduce the viscosity and thereby increase the mobility of the oil especially the residual oil). Three major categories of EOR have been found to be commercially of varying degrees: thermal recovery, gas injection (e.g. natural gas, N2 or CO2) and chemical injection (e.g. polymer flooding and microbial injection).
The EOR technique that has attracted the most new market interest is CO2-EOR. In the U.S., CO2 injection has been implemented through the Permian Basin of West Texas and eastern New Mexico, and is now also being pursued at varying extents in other states such as Kansas, Mississippi, Wyoming, Oklahoma, Colorado, Utah, Montana, Alaska and Pennsylvania.
CO2 is effective in recovering oil from a reservoir because it promotes swelling of the oil, reduces the viscosity and vaporizes portions of crude as it is being transported through the porous rock (Shawket Ghedan, 2009, “Global Laboratory Experience of CO2-EOR Flooding”, SPE 125581—incorporated herein by reference in its entirety). However, as CO2 is highly mobile, this technique encounters problems of viscous fingering, reservoir heterogeneity and gravity overriding or segregation, as the ability to control the mobility of CO2 is limited (S. I. Bakhtiyarov, A. K. Shakhverdiev, 2007, “Effect of Surfactant on Volume and Pressure of Generated CO2 Gas”, SPE 106902; B. Bai, R. B. Grigg, Y. Liu and Z. Zeng, 2005, “Adsorption Kinetics of Surfactant Used in CO2-Foam Flooding Onto Berea Sandstone”, SPE 95920; R. B. Grigg, B. Bai, 2005, “Sorption of Surfactant Used in CO2 Flooding onto Five Minerals and Three Porous Media”, SPE 93100; John D. Rogers, Reid B. Grigg, October 2001, “A Literature Analysis of the WAG Injectivity Abnormalities in the CO2 Process”, SPE Reservoir Evaluation & Engineering, 375-386—each incorporated herein by reference in its entirety).
Attempts to reduce the mobility of CO2 include the injection of CO2 in a supercritical fluid state or as carbonated water, which can also be accompanied by the injection of chemicals such as viscosifiers, surfactants and nanosilica particles for foam formation (Morten Gunnar Aarra, Arne Skauge, Stensbye Solbakken, 2013, “Supercritical CO2 Foam—The Importance of CO2 Density on Foams Performance”, SPE-165296-MS; M. M. Kulkarni and D. N. Rao, 2005, “Experimental Investigation of Miscible Secondary Gas Injection”, SPE 95975; Jianjia Yu, Di Mo, Ning Liu, Robert Lee, 2013, “The Application of Nanoparticle-Stabilized CO2 Foam for Oil Recovery”, SPE 164074; A. A. Espie, 2005, “A New Dawn for CO2 EOR”, IPTC 10935; Asghari, K., M. Nasehi Araghi, F. Ahmadloo and P. Nakutnyy, 2009, “Utilization of CO2 for Improving the Performance of Waterflooding in Heavy Oil Recovery,” Petroleum Society Journals; Sohrabi, M., M. Riazi, M. Jamiolahmady, S. Ireland, C. Brown, “Mechanisms of Oil Recovery by Carbonated Water Injection”, SCA2009-26; R. Farajzadeh, A. Andrianov, and P. L. J. Zitha, 2009, “Foam assisted oil recovery at miscible and immiscible conditions”, SPE 126410—each incorporated herein by reference in its entirety).
The use of surfactants in foam EOR is to reduce the mobility of the injected fluid by increasing the viscosity which leads to higher sweep displacement efficiency. The capillary forces are reduced due to reduction interfacial tension by the presence of the surfactant. Using surfactants to control the mobility of CO2 is technically viable, yet the efficiency of the surfactant-CO2 system often decreases sharply during clouding as a result of contact with crude oil, adsorption of surfactants, high salinity formation water and high reservoir temperature (Ingebret Fjelde, John Zuta and Ingrid Hauge, June 2009, “Retention of CO2-Foaming Agents on Chalk: Effects of Surfactant Structure, Temperature, and Residual Oil Saturation”, SPE Reservoir Evaluation and Engineering, 419-426; U.S. Pat. No. 4,060,727—each incorporated herein by reference in its entirety). These challenges have been the focus of research at the laboratory core flood and field scale simulation using commercial simulators like CMG-STARS (Guangwei Ren, Hang Zhang and Quoc P. Nguyen, 2011, “Effect of Surfactant Partitioning Between CO2 and Water on CO2 Mobility Control in Hydrocarbon Reservoirs”, SPE 145102; Viet Q. Le, Quoc P. Nguyen and Aaron W. Sanders, 2008, “A Novel Foam Concept with CO2 Dissolved Surfactants”, SPE 113370; A. Moradi-Araghi, E. L. Johnson, D. R. Zornes and K. J. Harpole, 1997, “Laboratory Evaluation of Surfactants for CO2-Foam Applications in the South Cowden Unit”, SPE 37218—each incorporated herein by reference in its entirety). For example, high crude oil presence can cause destabilizing effects on the CO2 foam (A. Moradi-Araghi, E. L. Johnson, D. R. Zornes and K. J. Harpole, 1997, “Laboratory Evaluation of Surfactants for CO2-Foam Applications in the South Cowden Unit”, SPE 37218—each incorporated herein by reference in its entirety). The identification of cost-effective, environmentally friendly materials that dissolve in supercritical CO2 for use in EOR has also posed a great challenge. Supercritical CO2-philes (materials soluble in supercritical CO2) are rare and use of these materials as surfactants was not possible due to the high pressures required to dissolve them (a result of their high molecular weight) and the inability to cost-effectively add a hydrophilic group for solubility in the bulk recovery fluid (water).
From the foregoing, it is evident that there remains an unmet need for a surfactant-CO2 system that works in actual reservoir conditions, despite the globally concerted effort. Most of the efforts attempted hitherto are plagued with deficiencies that restrict their applicability. For example, a majority of the aforementioned surfactants have not been tested in high saline environment. The inability of foam generation or instability of the generated foam means that the problem of CO2 high mobility has not been successfully tackled. Adsorption of the surfactant on the rock material is another factor which reduces the effectiveness of the foam system. Moreover, the number of foam experiments that have been conducted carbonate rocks is very limited; those conducted on long cores are even fewer.